Well testing systems and methods with mobile monitoring

ABSTRACT

A system includes a well testing apparatus and a mobile device to be carried by an operator of the well testing apparatus. The well testing apparatus can include a separator, a well control assembly upstream of the separator, a fluid management assembly downstream of the separator, and data acquisition devices positioned to collect data about operation of the well testing apparatus. The mobile device can display information about the operation of the well testing apparatus based on the collected data and enables mobile monitoring of the operation of the well testing apparatus by the operator as the operator moves about the well testing apparatus. Additional systems, methods, and devices are also disclosed.

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a continuation of and claims priority to U.S. Pat.Application Serial No. 16/310,987, filed Dec. 18, 2018, entitled “WELLTESTING SYSTEMS AND METHODS WITH MOBILE MONITORING,” which is a nationalstage application, filed under 35 U.S.C. §371 of International PatentApplication No. PCT/US2016/055092, filed on Oct. 3, 2016, entitled “WELLTESTING SYSTEMS AND METHODS WITH MOBILE MONITORING,” which claimsforeign priority to European Patent Application No. 16290119.3, filed onJun. 28, 2016, entitled “WELL TESTING SYSTEMS AND METHODS WITH MOBILEMONITORING,” each of which is incorporated by reference in its entiretyfor all purposes.

BACKGROUND Field

This disclosure relates to well testing systems, apparatuses, devices,and methods for executing a well test.

Description of the Related Art

Wells are generally drilled into subsurface rocks to access fluids, suchas hydrocarbons, stored in subterranean formations. The subterraneanfluids can be produced from these wells through known techniques.Operators may want to know certain characteristics of produced fluids tofacilitate efficient and economic exploration and production. Forexample, operators may want to know flow rates of produced fluids. Theseproduced fluids are often multiphase fluids (e.g., those having somecombination of water, oil, and gas), making measurement of the flowrates more complex. Surface well testing provides various informationabout the reservoir and its fluids, such as volumetric flow rates offluids produced from a well and properties of the produced fluids.Surface well testing equipment may be temporarily installed at awellsite for well test operations and then removed at the conclusion oftesting.

SUMMARY

Certain aspects of some embodiments disclosed herein are set forthbelow. It should be understood that these aspects are presented merelyto provide the reader with a brief summary of certain forms theinvention might take and that these aspects are not intended to limitthe scope of the invention. Indeed, the invention may encompass avariety of aspects that may not be set forth below.

Some embodiments of the present disclosure relate to a system includinga well testing apparatus and a mobile device to be carried by anoperator of the well testing apparatus. In one embodiment, the welltesting apparatus can include a separator, a well control assemblyupstream of the separator so as to route a multiphase fluid from a wellto the separator, a fluid management assembly downstream of theseparator so as to receive separated fluids from the separator, and dataacquisition devices positioned to collect data about operation of thewell testing apparatus. The mobile device can display information aboutthe operation of the well testing apparatus based on the collected dataand enables mobile monitoring of the operation of the well testingapparatus by the operator as the operator moves about the well testingapparatus.

In another embodiment, a method includes communicating data from sensorsof a well testing apparatus during a well test at a wellsite andreceiving the communicated data at a data acquisition system. The methodcan also include processing the received data and presenting a visualrepresentation of a well test parameter on a display of a mobile devicepresent at the wellsite based on the processed data.

In a further embodiment, a method includes receiving, on a mobile deviceduring a well test performed with a well testing apparatus, input froman operator of the well testing apparatus of an operational parameter ofthe well testing apparatus that is measured by the operator. The methodcan also include automatically transmitting the measured operationalparameter from the mobile device to a computer system during the welltest. The measured operational parameter can be stored in a database ofwell test operational data.

Various refinements of the features noted above may exist in relation tovarious aspects of the present embodiments. Further features may also beincorporated in these various aspects as well. These refinements andadditional features may exist individually or in any combination. Forinstance, various features discussed below in relation to theillustrated embodiments may be incorporated into any of theabove-described aspects of the present disclosure alone or in anycombination. Again, the brief summary presented above is intended justto familiarize the reader with certain aspects and contexts of someembodiments without limitation to the claimed subject matter.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features, aspects, and advantages of certain embodimentswill become better understood when the following detailed description isread with reference to the accompanying drawings in which likecharacters represent like parts throughout the drawings.

FIG. 1 generally depicts a well testing installation at a wellsite inaccordance with an embodiment of the present disclosure.

FIG. 2 is a block diagram representing functional groups of a welltesting apparatus in accordance with an embodiment of the disclosure.

FIG. 3 depicts the functional groups of the well testing apparatus ofFIG. 2 with control equipment for controlling certain well control andfluid management aspects of the well testing apparatus in accordancewith an embodiment of the disclosure.

FIG. 4 is a block diagram of components of a processor-based system thatcan be used to perform certain monitoring or control operations inaccordance with an embodiment of the disclosure.

FIGS. 5 and 6 are flowcharts representing processes for controllingoperation of a well testing apparatus in accordance with certainembodiments of the disclosure.

FIG. 7 depicts various equipment of a well testing apparatus inaccordance with an embodiment of the disclosure.

FIG. 8 is a diagram illustrating a mobile monitoring system with a welltesting apparatus in accordance with an embodiment of the disclosure.

FIG. 9 is a flowchart representing a process for conveying well testinformation to an operator via a mobile device and controlling a welltest apparatus in accordance with an embodiment of the disclosure.

FIG. 10 is a flowchart representing a process for recording andtransmitting well test operational data via a mobile device inaccordance with an embodiment of the disclosure.

FIG. 11 depicts various equipment of a well testing apparatus, includinga pump manifold skid and tank manifold skids, in accordance with anembodiment of the disclosure.

FIGS. 12-14 depict various manifolds that can be mounted on the pumpmanifold skid of FIG. 11 in accordance with certain embodiments of thedisclosure.

FIG. 15 depicts a pump manifold skid in accordance with an embodiment ofthe disclosure.

FIG. 16 depicts a tank manifold skid in accordance with an embodiment ofthe disclosure.

FIG. 17 is a schematic representation of pipework of the tank manifoldskid of FIG. 16 in accordance with an embodiment of the disclosure.

FIGS. 18-20 show several possible arrangements of tanks, tank manifoldskids, and a pump manifold skid in accordance with certain embodimentsof the disclosure.

DETAILED DESCRIPTION

It is to be understood that the present disclosure provides manydifferent embodiments, or examples, for implementing different featuresof various embodiments. Specific examples of components and arrangementsare described below for purposes of explanation and to simplify thepresent disclosure. These are, of course, merely examples and are notintended to be limiting.

When introducing elements of various embodiments, the articles “a,”“an,” “the,” and “said” are intended to mean that there are one or moreof the elements. The terms “comprising,” “including,” and “having” areintended to be inclusive and mean that there may be additional elementsother than the listed elements. Moreover, any use of “top,” “bottom,”“above,” “below,” other directional terms, and variations of these termsis made for convenience, but does not mandate any particular orientationof the components.

Embodiments of the present disclosure generally relate to well testingoperations at a wellsite. More particularly, at least some embodimentsrelate to a surface well testing apparatus that can be monitored andcontrolled remotely. For example, such a well testing apparatus caninclude a control and monitoring system that enables local control ofthe well testing apparatus. Additional embodiments include a welltesting apparatus having a mobile monitoring system, in whichoperational information for the well test can be communicated to anoperator via a mobile device.

Further, in some embodiments a well testing apparatus may be provided asa modular system to facilitate its transport to, and installation at, awellsite. Such a modular well testing apparatus may include tankmanifold skids and a pump manifold skid. The pump manifold skid caninclude manifolds for routing fluids received from a separator of thewell testing apparatus and the tank manifold skids can be interconnectedwith each other to form manifolds for routing fluids between the pumpmanifold skid and fluid tanks connected to the manifolds of theinterconnected tank manifold skids.

Turning now to the drawings, a wellsite 10 is generally depicted in FIG.1 in accordance with one embodiment. As presently shown, a well testingapparatus or installation 12 is deployed at the wellsite 10 and iscoupled to wellhead equipment 14 installed at a well 16. The wellheadequipment 14 can include any suitable components, such as casing andtubing heads, a production tree, and a blowout preventer, to name but afew examples. Fluid produced from the well 16 can be routed through thewellhead equipment 14 and into the well testing apparatus 12. It will beappreciated that the wellsite 10 can be onshore or offshore. In offshorecontexts, the well testing apparatus 12 can be installed on an offshoredrilling rig at the wellsite 10.

In many cases, operation of a well testing apparatus can be split intofour elementary functions: well control, separation, fluid management,and burning. In an example of a well testing apparatus 12 depicted inFIG. 2 , these functions can be carried out by functional groupsincluding a well control assembly 20, a separation portion 22, a fluidmanagement assembly 24, and a burning operation portion 26. Whilecertain elements of the well control apparatus 12 are shown in thepresent figure and discussed below, it is noted that the apparatus 12may include other components in addition to, or in place of, thosepresently illustrated and discussed. For example, the well controlapparatus 12 can include a gas specific gravity meter, a water-cutmeter, a gas-to-oil ratio sensor, a carbon dioxide sensor, a hydrogensulfide sensor, or a shrinkage measurement device. These and othercomponents could be used at any suitable location within the wellcontrol apparatus 12, such as upstream or downstream of a separator(e.g., as part of the well control assembly 20 or the fluid managementassembly 24).

Effluents from the well 16 can be received in the well control assembly20 and then routed to the separation portion 22 downstream of theassembly 20. The well control assembly 20 is shown in FIG. 2 as havingflow control equipment in the form of various manifolds (i.e., an intakemanifold 30, a choke manifold 32, and an additional manifold 34) forreceiving and routing the well effluents. The depicted well controlassembly 20 also includes a heat exchanger 36, which may be provided asa steam-heat exchanger, and a flow meter 38 for measuring flow of fluidthrough the well control assembly 20.

The well control assembly 20 conveys the effluents received from thewell 16 to a separator 42. The features of the separator 42 can varybetween embodiments. For example, the separator 42 can be a horizontalseparator or a vertical separator, and can be a two-phase separator(e.g., for separating gas and liquids) or a three-phase separator (e.g.,for separating gas, oil, and water) in different embodiments. Further,the separator 12 can include any of various mechanisms that facilitateseparation of components of the incoming fluid, such as diffusers, mistextractors, vanes, baffles, and precipitators to name several examples.

In many instances, the well effluents are provided in the form of amultiphase fluid having a combination of oil, gas, and water. In atleast some embodiments the separator 42 can be used to generallyseparate the multiphase fluid into its oil, gas, and water phases, andthese separate fluids may be routed away from the separator 42 to thefluid management assembly 24. As will be appreciated by those skilled inthe art, these separated fluids may not be entirely homogenous. That is,separated gas exiting the separator 42 can include some residual amountof water or oil and separated water exiting the separator 42 can includesome amount of oil or entrained gas. Likewise, separated oil leaving theseparator 42 can include some amount of water or entrained gas.

Referring again to FIG. 2 , the separated fluids can be routeddownstream from the separator 42 to the fluid management assembly 24.The fluid management assembly 24 includes flow control equipment, suchas various manifolds and pumps (generally represented by block 44) forreceiving fluids from the separator and conveying the fluids to otherdestinations, as well as additional manifolds 46 for routing fluid toand from fluid tanks 48. Although two manifolds 46 and two tanks 48 aredepicted in FIG. 2 , it is noted that the number of manifolds 46 andtanks 48 can be varied. For instance, in one embodiment the fluidmanagement assembly 24 includes a single manifold 46 and a single tank48, while in other embodiments the fluid management assembly 24 includesmore than two manifolds 46 and more than two tanks 48.

The manifolds and pumps represented by block 44 can include a variety ofmanifolds and pumps, such as a gas manifold, an oil manifold, an oiltransfer pump, a water manifold, and a water transfer pump. In at leastsome embodiments, the manifolds and pumps of block 44 can be used toroute fluids received from the separator 42 to the fluid tanks 48 viathe additional manifolds 46, and to route fluids between tanks 48. Themanifolds and pumps of block 44 can also be used to route fluidsreceived from the separator 42 directly to burners 52 for burning gasand oil (bypassing the tanks 48) or to route fluids from the tanks 48 tothe burners 52.

As noted above, the components used in the apparatus 12 may vary betweendifferent applications. Still further, the equipment within eachfunctional group of the well testing apparatus 12 may also vary. Forexample, the heat exchanger 36 could be provided as part of theseparation portion 22, rather than of the well control assembly 20.

In certain embodiments, the well testing apparatus 12 is a surface welltesting apparatus that can be monitored and controlled remotely. Remotemonitoring of the well testing apparatus can be effectuated with sensorsinstalled on various components of the functional groups of theapparatus, as discussed in greater detail below. In some instances, amonitoring system (e.g., sensors, communication systems, andhuman-machine interfaces) of the well testing apparatus 12 enablesmonitoring of each of its well control, separation, fluid management,and burning functions, though fewer functions could be monitored inother instances.

The well testing apparatus 12 may also include various control systemsto enable remote control of components of the apparatus. For instance,the well testing apparatus 12 is shown in FIG. 3 as including controlequipment 60 that enables remote control of components of the wellcontrol assembly 20, as well as control equipment 62 that enables remotecontrol of components of the fluid management assembly 24. The controlequipment 60 includes a controller 64 connected to various components ofthe well control assembly 20 via input/output modules 66. Morespecifically, the input/output modules 66 allow communication betweenthe controller 64 and various sensors and actuators of the manifolds 30,32, and 34. A human-machine interface (HMI) 68 allows communicationbetween the controller 64 and an operator. Similarly, the controlequipment 62 includes a controller 74 connected to various sensors andactuators of manifolds and pumps of the fluid management assembly 24 viainput/output modules 76, as well as an HMI 78 that enables communicationbetween the controller 74 and the same or a different operator.

The controllers 64 and 74 can be provided in any suitable form, such asprogrammable logic controllers. The HMIs 68 and 78 can also take anysuitable forms, such as a device with display screens and physical keysor buttons, or devices with touchscreens that enable user input on thescreens themselves. The HMIs 68 and 78 can display information to theoperator, such as measurements or operational status of well controlapparatus 12, while allowing the operator to provide commands (via userinput) to the controllers 64 and 74.

In at least some embodiments, the well testing apparatus 12 enableslocal control of components of one or more of the functional groups ofthe apparatus 12. For example, the control equipment 60 can be providedlocally as part of the well control assembly 20, and the controlequipment 62 can be provided locally as part of the fluid managementassembly 24, rather than providing the control equipment 60 and 62 at alocation remote from the assemblies 20 and 24 (e.g., in a cabin at thewellsite). Indeed, as later discussed, the control equipment 60 and 62can be mounted on skids shared with flow control equipment of theassemblies 20 and 24, respectively. The controllers 64 and 74 canoperate as a local intelligence for controlling connected equipment ofthe assemblies 20 and 24. The local intelligence can be designedspecifically for a given function of the well control apparatus (e.g.,fluid management). With respect to the well control assembly 20, thelocal intelligence embodied in controller 64 can be used to actuatevalves of the manifolds 30, 32, and 34, for instance. By way of furtherexample, the local intelligence of controller 74 can be used to actuatepumps or valves of manifolds of the fluid management assembly 24.

In addition to the HMIs 68 and 78 that can be provided at or nearequipment of the well testing apparatus 12, duplicate HMIs 82 and 84 canbe provided away from the assemblies 20 and 24 at a control cabin 86 atthe wellsite or some other location removed from the assemblies 20 and24. The duplicate HMIs 82 and 84 provide redundancy, facilitating bothlocal control at the equipment of the well testing apparatus 12 (via theHMIs 68 and 78) and global control from a location further away from thecontrolled equipment (via HMIs 82 and 84). This architecture allows themain control point for a given function (e.g., HMI 68 or 78) to bepositioned next to the controlled equipment, while having a back-upcontrol point in the control cabin or other location away from thecontrolled equipment. Further, controlling the flow control equipment orother equipment of the well testing apparatus 12 via HMI 68 or 78positioned with the controlled equipment, rather than with HMI 82 or 84removed from the controlled equipment, may allow an operator to directlysense certain contextual clues about operation of the well controlassembly independent of the HMI 68 or 78 used by the operator. Forexample, while using the HMI 78, the operator may hear noises or feelvibrations from components of the well testing assembly 12. Suchadditional, sensory clues may provide insight into the operation of thewell testing assembly 12 and inform decision-making by the operatorregarding control of the assembly.

Although control equipment 60 and 62 enables local control of twofunctions of the well testing apparatus 12 (i.e., well control and fluidmanagement), other embodiments may be configured to provide localcontrol of a different number of functions. For instance, controlequipment 60 or control equipment 62 could be omitted to provide localcontrol of a single function of the apparatus 12, or additional controlequipment could be provided for local control of other functions.Further, while the control equipment 60 and 62 may be used to controlflow control equipment (e.g., manifolds and pumps) of the assemblies 20and 24, the control equipment 60 and 62 could also or instead be used tocontrol other components of the well testing apparatus 12.

In some embodiments the local intelligence is designed to control just agiven elementary function, which offers flexibility to remotely controlone or several elementary functions by varying the number of localintelligences coupled to components of the well testing apparatus 12.Furthermore, the equipment within a functional group may vary (e.g., thenumber of tanks for fluid management). To accommodate such variability,the hardware and software of the control system in at least someembodiments are modular. With respect to varying numbers of fluid tanksin the fluid management assembly 24, for instance, each fluid tank canbe provided as part of an individual physical module (e.g., including asingle manifold 46 and a single tank 48) and a corresponding softwaremodule can be implemented in configurable control software of thecontroller 74.

The controllers 64 and 74, as well as various other data monitoring orcontrol components discussed below, may be provided as processor-basedsystems. Such processor-based systems may include programmable logiccontrollers or programmed general-purpose computers, to name just twoexamples. An example of a processor-based system 90 is generallyprovided in FIG. 4 . In this depicted embodiment, the system 90 includesat least one processor 92 connected by a bus 94 to volatile memory 96(e.g., random-access memory) and non-volatile memory 98 (e.g., flashmemory). Coded application instructions 100 (such as the programmedlocal intelligence of the controllers 64 and 74) and data 102 are storedin the non-volatile memory 98. The instructions 100 and the data 102 mayalso be loaded into the volatile memory 96 (or in a local memory 104 ofthe processor) as desired, such as to reduce latency and increaseoperating efficiency of the system 90. The coded applicationinstructions 100 can be provided as software that may be executed by theprocessor 92 to enable various functionalities described herein. In atleast some embodiments, the application instructions 100 are encoded ina non-transitory, computer-readable storage medium, such as the volatilememory 96, the non-volatile memory 98, the local memory 104, or aportable storage device (e.g., a flash drive or a compact disc).

An interface 106 of the system 90 enables communication between theprocessor 92 and various input devices 108 and output devices 110. Theinterface 106 can include any suitable device that enables suchcommunication, such as a modem or a serial port. In some embodiments,the input and output devices 108 and 110 include controlled componentsof the well testing apparatus 12 and an HMI that enables communicationbetween the system 90 and a user.

In various embodiments, controllers of the well testing apparatus 12,such as controllers 64 and 74, are configured (e.g., with programmedsoftware) to control equipment of the apparatus 12 according todifferent modes. In one mode, which can be referred to as “manual remotecontrol,” an operator interacts with an HMI to control a given valve orother component of the well testing apparatus 12. For example, theoperator may instruct a particular valve to open or close. In such anoperating mode, the operator is fully responsible for the instructedaction and there is no safety intelligence to support the decision orwarn the operator of an improper command.

A different mode of operation, which can be referred to as“semi-automated remote control,” is similar to the manual remote controlmode noted above, but with local intelligence of a controller validatingthe operator’s action against safety, quality, or other constraints.(These constraints can be stored as data in a memory of the controller.)For instance, one constraint may be that the operator may not opentogether a valve that would allow fluid to pass to a flare or otherburner on a starboard side of a rig and a valve that would allow fluidto pass to a flare or other burner on the port side of the rig. That is,it can be undesirable to flare gas or burn oil on both the port andstarboard sides of the rig simultaneously, and a constraint may beprogrammed into the control system so as to avoid such an occurrence.

A further example of a semi-automated remote control process isgenerally represented by flowchart 118 in FIG. 5 . In this embodiment, amultiphase fluid is routed to a separator (block 120), which separatesthe multiphase fluid (block 122) into separate fluids as describedabove. The separated fluids are routed away from the separator (block124), such as to fluid tanks for storage or to burners or otherdestinations for disposal. The flow of the separated fluids downstreamfrom the separator can be controlled by actuating pumps and valves ofthe fluid management assembly 24. Such flow can include routing of theseparated fluids to a tank or to a disposal destination, routingseparated fluids from a tank to a disposal destination, or routingseparated fluids from one tank to another tank. The operator canindicate a requested command for controlling a valve or othercomponent-such as opening or closing a valve or starting a pump-via anHMI in communication with the controller.

In a manual remote control mode, the controller may transmit anactuation signal to the controlled component in response to receipt ofthe user input of a requested command at the HMI. For example, a usercan command a particular valve to open via the HMI, and the controllerwould then transmit an actuation signal to the valve actuator inresponse to the user input without considering the current operationalstatus of other components of the well testing apparatus or the effectof actuating the valve as commanded. In contrast, in a semi-automatedremote control mode, the received user indication of a requested command(block 126) is validated against constraints (block 128), such as withthe local intelligence of the controller, so as to avoid undesiredoperation of the well testing apparatus. If the requested command wouldviolate a given constraint-such as a safety constraint that one valvenot be open at the same time as a particular different valve-the commandwould not be performed. In such a case, an error message could beprovided to the operator via the HMI. The local intelligence in thisexample could assess the operating status of the two valves to determinewhether a first of the two valves is closed before sending an actuationsignal from the controller to the actuator of the second of the twovalves to open the second valve. Once validated against the constraints,the requested command is performed (block 130) by sending the actuationsignal to the controlled valve or other component.

Another mode of operation of the controller can be referred to as“automated remote control.” In this control mode, the action of theoperator from a remote control HMI launches a procedure resulting inmultiple actions to be automatically performed by the controller. Forexample, an operator may select, via the HMI, an option to “transferwater from tank A to tank B” (e.g., the two fluid tanks 48 in FIG. 3 ).In response to this single selection, the controller may automaticallysend actuation signals to initiate a sequence of opening an inlet valveof tank B, opening an outlet valve of tank A, and starting a water pump,among other operations. Procedures can be programmed to line up a givenflow path from a source (such as the separator 42 or a tank 48) to adestination (such as to another tank 48 or a burner 52) for a givenfluid (such as oil).

An example of an automated remote control process is generallyrepresented by flowchart 136 in FIG. 6 . In this embodiment, anindication of a user-requested operational procedure is received (block138), such as through user input at a remote control HMI. In theautomated remote control mode, the requested procedure can beautomatically compared to an interlock matrix (block 140) to prevent thelaunch of incompatible sequences together (such as “flow oil to burnerport side” and “flow gas to flare starboard side”). This is generallyrepresented by decision block 142, in which local intelligence candetermine whether the requested operational procedure is permissible(e.g., whether it is compatible or incompatible with another procedurebeing performed or with the current operational state of the welltesting apparatus). If the requested procedure is not permissible, thecontroller does not perform the procedure (block 144) and an errormessage can be given to the operator. If the requested procedure isdetermined to be permissible, it is then automatically performed (block146), such as by sending actuation signals to the components to becontrolled. It is further noted that the controller can include an eventlogger that records events, operator actions, error messages, and alarmsfor the control system.

Surface well testing installations may use a large deck space to spotand fix equipment and interconnect them with piping. As discussed above,the well testing apparatus 12 may take many forms. As one example, thewell testing apparatus 12 may be provided in the form of a surface welltesting system or apparatus 150 generally illustrated in FIG. 7 . Inthis depicted embodiment, a multiphase fluid (represented here by arrow152) enters a flowhead 154 and is routed to a separator 170 through asurface safety valve 156, a steam-heat exchanger 160, a choke manifold162, a flow meter 164, and an additional manifold 166. The apparatus 150in FIG. 7 also includes a chemical injection pump 158 for injectingchemicals into the multiphase fluid flowing toward the separator 170.

In the presently depicted embodiment, the separator 170 is a three-phaseseparator that generally separates the multiphase fluid into gas, oil,and water components. The separated gas is routed downstream from theseparator 170 through a gas manifold 174 to either of the burners 176for flaring gas and burning oil. The gas manifold 174 includes valvesthat can be actuated to control flow of gas from the gas manifold 174 toone or the other of the burners 176. Although shown next to one anotherin FIG. 7 for clarity, the burners 176 may be positioned apart from oneanother, such as on opposite sides of a rig.

The separated oil from the separator 170 is routed downstream to an oilmanifold 180. Valves of the oil manifold 180 can be operated to permitflow of the oil to either of the burners 176 or either of the tanks 182and 184. The tanks 182 and 184 can take any suitable form, but aredepicted in FIG. 7 as vertical surge tanks each having two fluidcompartments. This allows each tank to simultaneously hold differentfluids, such as water in one compartment and oil in the othercompartment. An oil transfer pump 186 may be operated to pump oilthrough the well testing apparatus 150 downstream of the separator 170.The separated water from the separator 170 is similarly routed to awater manifold 190. Like the oil manifold 180, the water manifold 190includes valves that can be opened or closed to permit water to flow toeither of the tanks 182 and 184 or to a water treatment and disposalapparatus 194. A water transfer pump 192 is used to pump the waterthrough the system.

As will be appreciated, the well test area in which the well testingapparatus 150 (or other embodiments of a well testing apparatus) isinstalled may be classified as a hazardous area. In some embodiments,the well test area is classified as a Zone 1 hazardous area according toInternational Electrotechnical Commission (IEC) standard60079-10-1:2015. The various equipment of the well testing apparatusesdescribed herein, including flow control equipment and controllers, maybe positioned within such a Zone 1 hazardous area.

Referring again to FIG. 7 , a cabin 196 at the wellsite may acquire datafrom the well testing apparatus 150. This acquired data can be used tomonitor and control the well testing apparatus 150. In at least someinstances, the cabin 196 is set apart from the well test area having thewell testing apparatus 150 in a non-hazardous area. This is representedby the dashed line 198 in FIG. 7 , which generally serves as ademarcation between the hazardous area having the well testing apparatus150 and the non-hazardous area of the cabin 196.

The equipment of a well testing apparatus is monitored during a welltesting process to verify proper operation and facilitate control of theprocess. Such monitoring can include taking numerous measurements duringthe well test, examples of which include choke manifold temperature andpressures (upstream and downstream), heat exchanger temperature andpressure, separator temperature and pressures (static and differential),oil flow rate and volume from the separator, water flow rate and volumefrom the separator, and fluid levels in tanks of the apparatus. In someinstances, these data are recorded manually by an operator who walksaround the well test area and records the measurements and other processinformation on a sheet of paper (e.g., a reading sheet) to inform futuredecision-making regarding control of the well test. With the variousequipment of the well testing apparatus spread about the well test area,such manual measurement collection can be time-consuming. Taking care toavoid tripping hazards in the well test area and climbing up verticaltanks to read fluid levels in the tanks further increase the time spentmanually collecting the process information.

In accordance with at least some embodiments of the present technique,however, a mobile monitoring system is provided with a surface welltesting installation. This enables monitoring of the well test processon a mobile device (e.g., a mobile device suitable for use in Zone 1hazardous area, like the well test area). Various information can beautomatically acquired by sensors and then presented to an operator viathe mobile device. The mobile monitoring system may provide variousfunctions, such as a sensor data display, video display, sensor or videoinformation interpretation for quality-assurance and quality-controlpurposes, and a manual entry screen (e.g., for a digital tally book forrecording measurements taken by the operator). Further, the monitoringsystem can be modular and configurable so it may be implemented on anywell testing installation that is equipped according to the presenttechniques.

An example of a mobile monitoring system 200 is generally depicted witha well testing apparatus in FIG. 8 . As noted above, a well testingapparatus 12 may be split into four elementary functions (well control,separation, fluid management, and burning operation), and the equipmentused in the apparatus 12 for each function can vary between embodiments.The well testing apparatus depicted in FIG. 8 includes the samefunctional groups and equipment described above with respect to FIG. 2 ,but is equipped with data acquisition devices in the form of sensors 202and cameras 204 for monitoring the well testing functions. In thepresently depicted embodiment, the sensors 202 and cameras 204 aredeployed to enable monitoring of each of the well testing functionspresented above. More specifically, the sensors 202 are installed onvarious components of the well testing equipment and the cameras 204 maybe positioned next to booms of the burners 52 to capture image data(e.g., video) of burner operation. In other embodiments, however, amobile monitoring system could be used to monitor fewer well testingfunctions. And while the system depicted in FIG. 8 includes cameras 204for monitoring the burning operation function and sensors 202 formonitoring components of the well control, separation, and fluidmanagement functions, it will be appreciated that sensors 202 can beused to monitor the burning operation function and that cameras 204 canbe used to monitoring the well control, separation, and fluid managementfunctions. Various data may be acquired with the sensors 202 and cameras204, non-limiting examples of which include pressure measurements,temperature measurements, flow rates, top and interface fluid levels intanks, and image data (static or video).

The data acquired by the sensors 202 and cameras 204 is communicated toa computer system 208, which may process and store the received data. Inthe presently depicted embodiment, the sensors 202 are wireless sensorsthat wirelessly transmit data to the computer system 208 via a wirelessgateway 210. Any suitable wireless communication standard may be used;in at least one instance, the sensors 202 are HART® wireless sensors andthe wireless gateway is a HART® wireless gateway. Although the sensors202 are shown as wireless sensors in FIG. 8 , it is noted any of thesesensors 202 could instead be provided as a wired sensor in communicationwith the computer system 208. Further, the cameras 204 can transmit datain any suitable manner. Although data from the cameras 204 could betransmitted wirelessly, in at least some embodiments the cameras 204send video or other data to the computer system 208 over a wiredconnection.

The computer system 208 communicates information based on the dataacquired with the sensors 202 or cameras 204 to a mobile device 214 overa wireless network via a wireless access point, such as a WI-FI® router212. In some instances, the wireless network can include wirelessrepeaters to improve communication signal range and strength within thewell test area. In one embodiment, the mobile device 214 may receivewirelessly transmitted data directly from one or more sensors 202 orcameras 204.

The mobile device 214 can be carried by an operator 218 within a welltest area. The mobile device 214 is a human-machine interface thatincludes a screen for showing information about a well testing process.More specifically, the mobile device 214 is configured to displayinformation (generally represented by arrow 216) on the screen to theoperator 218 about the operation of the well testing apparatus based onthe data acquired with the sensors 202 or cameras 204. This enablesmobile monitoring of the operation of the well testing apparatus by theoperator as the operator moves about the well test area. In at leastsome embodiments, the mobile device displays such information in realtime, thus enabling real-time mobile monitoring of the well testingprocess by an operator in the well test area. Any type of informationmay be displayed, such as sensor data from sensors 202, video capturedby the cameras 204, processed data, or interpreted data. Examples ofsuch interpreted data include information regarding choke plugging,choke erosion, carry-over, carry-under, and emulsion detection andcharacterization in tanks. Additionally, by displaying such processinformation on the mobile device 214, the operator 218 can assess theurgency of the process status, prioritize tasks, and take appropriateaction (generally represented by arrow 220), such as opening or closingvalves, in a timely manner. Alarms may also be displayed, and alarms andalarm management actions (such as acknowledgement or reset) can berecorded in an event logger.

In at least some embodiments, the mobile device 214 is certified forusage in Zone 1 hazardous areas and is carried by an operator 218 withina Zone 1 hazardous area (e.g., the well test area), while the computersystem 208 is located in a non-hazardous area (e.g., a lab cabin).Dashed line 224 in FIG. 8 generally represents a boundary between thesehazardous and non-hazardous areas. Although a single mobile device 214is shown in FIG. 8 for simplicity, it will be appreciated that themobile monitoring system could include multiple mobile devices 214(which could be carried by different operators) that receive well testprocess information from the computer system 208. Mobile devices 214could take any suitable form, such as tablet computers or smartphones.Further, the computer system 208 and mobile devices 214 areprocessor-based systems that include various processing and memorycomponents, such as those described above with respect to system 90 ofFIG. 4 . Software or other coded instructions resident in the computersystem 208 or mobile devices 214 can be used to facilitate the mobilemonitoring and control functionalities described herein. Information canbe displayed to a user on a screen of the computer system 208 or of amobile device 214 in any suitable manner, such as via a webpage or amobile device application.

As discussed above, information based on data acquired with the sensors202 and the cameras 204 can be displayed to users of the computer system208 or mobile devices 214. In some embodiments, including thatillustrated in FIG. 8 , the computer system 208 and the one or moremobile devices 214 are configured to display video 230 in a window ontheir respective screens, while also displaying additional information(e.g., information 232 and 234) on their screens based on data acquiredfrom one or more sensors 202. In other instances, the video 230 and theadditional information 232 and 234 could be displayed at differenttimes, such as consecutively rather than concurrently. While thecomputer system 208 and the mobile device 214 are depicted in FIG. 8 asdisplaying identical graphical information on their screens (i.e., video230 and information 232 and 234), the content of the informationdisplayed on their screens may differ in other instances. For example,less information may be displayed on the screen of the mobile device insome cases due to screen size constraints.

In order to constantly monitor burning operations, the monitoring system200 can include at least one camera 204 pointed to each burner. In oneembodiment, two cameras 204 are pointed to a first burner 52 and twoother cameras 204 are pointed to a second burner 52. The cameras 204(which can detect visible or infrared light) are positioned to acquireimage data (video or static) about operation of the burners 52 duringburning of oil or gas. The acquired image data can be displayed on ascreen of the computer system 208 (such as in a lab cabin) or on amobile device 214 in the well testing area. The cameras 204 can beindividually controlled from the computer system 208 (or from a mobiledevice 214) to pan, tilt, or zoom the cameras. In at least someembodiments, the video data acquired with the cameras 204 hashigh-definition resolution (e.g., 720p) and a frame rate of at least 25frames per second. The cameras 204 can also include microphones, andsound captured by these microphones can be transmitted to the computersystem 208 and made available to users (e.g., in the lab cabin). Thevideo and sound captured with the cameras 204 and transmitted to thecomputer system 208 may be recorded for future use, such as for replay,traceability, contractual engagement, and post-job troubleshooting.

By way of further example, a process for conveying well test informationvia a mobile device is generally represented by flowchart 242 in FIG. 9. This embodiment includes acquiring data (block 244) for a well testingapparatus during a well test, such as with a sensor 202. The acquireddata is transmitted to a data acquisition system, such as the computersystem 208 or the mobile device 214, which processes the acquired data(block 246). Such processing can include any of a variety of actions,such as storing the data, analyzing the data, interpreting the data, orforwarding the data to another device or location. The processrepresented in FIG. 9 also includes presenting a visual representation(block 248) of a well test parameter on a display of a mobile device(e.g., mobile device 214) present at the wellsite based on the processeddata. This can include, for example, displaying real-time values of welltest measurements directly acquired by sensors 202 or interpreted frommeasurements taken by the sensors 202. In some instances, processing thedata in block 246 includes identifying trends in the data, and a visualrepresentation of this identified trend may then be presented on ascreen of the mobile device 214 or of the computer system 208.

The process represented in FIG. 9 also includes controlling operation ofthe well testing apparatus (block 250), such as in response toinformation provided to an operator via the computer system 208 ormobile device 214. In some instances, an operator may manually controloperation, such as by walking to a particular valve of the well testingapparatus and then opening or closing the valve. In other instances,however, the well testing apparatus may include remote controlfunctionality, such as that described above, and an operator mayinitiate control via a human-machine interface. In one such embodiment,the control can be effected by an operator through user input to amobile device 214 carried by the operator. That is, the mobile device214 may communicate a command to a controller (e.g., controller 74) toactuate a component or begin an actuation sequence for multiplecomponents.

Additionally, in some embodiments the mobile device 214 can be used as adigital tally book for manual data recording by an operator. Forexample, the operator can collect well test measurements (such asmeasurements of fluid properties) independent of the mobile device 214,and then enter those measurements in the mobile device 214. The dataentered into the mobile device 214 can be transmitted to another system(e.g., computer system 208) in a real-time or delayed manner.

An example of a process for recording and transmitting well testoperational data via a mobile device is generally represented byflowchart 260 in FIG. 10 . This embodiment includes receiving from anoperator, on a mobile device (such as mobile device 214), input of anoperational parameter measured by the operator during a well test (block262). The process also includes automatically transmitting the measuredparameter to a computer system (e.g., computer system 208) during thewell test (block 264). In at least one embodiment, the measuredparameter is transmitted from the mobile device to the computer systemover a wireless network. The measured parameter can be stored (block266) in a database of well test operational data. The measured parametercan also be processed by the computer system and an indication of themeasured parameter can be shown (block 268) to a user of the computersystem. The process represented in FIG. 10 also includes controllingoperation of the well testing apparatus (block 270). For example, a userof the computer system can input a command to remotely control the welltesting apparatus based on the indication of the measured parameter, anda controller of the well testing apparatus can send an actuation signalto one or more components in response to the command.

The mobile monitoring embodiments discussed above enable informationabout a well testing apparatus to be conveyed to an operator within awell test area in charge of control of a well test operation. Amongother things, this may facilitate increased understanding and awarenessamong operators of the current status of the operation to aid in makingcontrol decisions. Certain embodiments of the mobile monitoring systemsmay also improve operational quality and safety, such as by reducingtripping hazards in the well test area (as the operator does not have togo read each sensor), reducing working at height hazards (the operatordoes not have to climb up vertical tanks to read fluid levels), reducingpollution risk (early detection of non-efficient burning conditions),and improving data-based decision-making processes (process overview andinterpreted diagnostic information may enable decisions to be made in amore timely manner).

As noted above, the well testing apparatus 12 of some embodiments can beprovided as a modular system in which modules for performing variousfunctions of the well testing apparatus 12 are assembled together andthen used for well testing operations at a wellsite. For example, a welltesting apparatus 12 can include a pump manifold skid and a tankmanifold skid, as described in greater detail below. In at least someembodiments, these skids gather the piping-related equipment (valves,fixed piping lines) and the pumps (water and oil transfer pumps) thatenable the management of single phase fluids downstream of a separator.The pump manifold skid can include automated manifolds and pumps toroute fluids between separators, tanks, and disposal equipment (e.g.,flares and other burners). The tank manifold skid connects to a fluidtank, such as a two-compartment tank, and includes actuated valves thatenable opening and closing the inlet, outlet, and drain for eachcompartment. A control system can be integrated on these skids, and inat least one embodiment includes a local intelligence installed on thepump manifold skid. In some instances, a single pump manifold skid isused in a well testing apparatus 12, while the number of tank manifoldskids is equal to the number of fluid tanks deployed in the apparatus toreceive fluid from the pump manifold skid. Each tank manifold skid maybe self-contained and may include the associated control systemaccessories used to operate and control the valves.

Equipment footprint optimization may be desirable, particularly inlocations where space is limited, such as on offshore rigs. Reduction inrig up/rig down time and minimal manual intervention may also bedesirable, since they can be directly correlated to cost savings. In atleast some embodiments, these skids are designed to reduce the surfacewell testing installation footprint, to reduce the rig up/rig down timeand effort, and to be modular in terms of layout, and are also automatedto reduce manual intervention during operations. The modularity of theseskids allows them to be assembled in different configurations toaccommodate the varied spatial constraints for different rigs and toaccommodate the varied processes for different well tests.

These skids can also be designed for use in offshore conditions (roll,pitch, heave, etc.). For such offshore uses, the skids can be secured toa rig platform with clamps. Bumper protection may be provided on theskids and accessories such as guides may be provided for ease ofinstallation with a crane in sea conditions (roll, pitch, etc.). In someembodiments, the tank manifold skids are connected to the tanks and toeach other with rigid bolted connections to distribute the deck load.The skids may be designed to withstand the transit, environmental, andfatigue loads, such as stipulated in DNVGL-OS-E101 (promulgated in July2015 by DNV GL Group) for temporary offshore well test installations.

Further, in some embodiments the skids can be pre-assembled with pipingand a pneumatic and electrical control system; in such cases,installation may be limited to interconnecting piping, pneumatic hoses,and electrical cables with connectors. Any desired walkways forfacilitating access by operators can be installed in a fixed mannerwithout bolting. In further embodiments, the tank manifold skids and thepump manifold skid have automated equipment and a control system toenable remote control, such as described above.

By way of example, the well testing apparatus 12 may be provided in theform of a surface well testing apparatus 280, as generally depicted inFIG. 11 . The well testing apparatus 280 is generally similar to thewell testing apparatus 150 described above and includes many of the samecomponents. But rather than having gas manifold 174, oil manifold 180,oil transfer pump 186, water manifold 190, and water transfer pump 192separately positioned about the well test area, the well testingapparatus 280 includes a pump manifold skid 284 on which variousmanifolds and pumps are mounted. More specifically, the flow controlcomponents mounted on the pump manifold skid include a gas manifold 294,an oil manifold 296, an oil transfer pump 298, a water manifold 302, anda water transfer pump 304 for routing gas, oil, and water between theseparator 170, tanks 290 and 292, the burners 176, and water disposalequipment 194.

The depicted well testing apparatus 280 also includes tank manifoldskids 286 and 288 that route fluid between the pump manifold skid 284and connected tanks 290 and 292. The tanks 290 and 292 are generallydepicted in FIG. 11 as two-compartment, vertical surge tanks, thoughthey could take different forms in other embodiments. Further, thenumber of tanks 290 and 292 and the number of associated tank manifoldskids 286 and 288 may also vary between embodiments. In at least someinstances, the number of such fluid tanks is equal to the number of thetank manifold skids and each fluid tank has its own tank manifold skid.That is, the tank manifold skids are connected to associated tanks in aone-to-one ratio. Other embodiments may include a different ratio oftank manifold skids and associated tanks, such as one-to-two,one-to-three, or one-to-four.

Examples of manifolds and pumps mounted on the pump manifold skid 284are depicted in FIGS. 12-14 in accordance with certain embodiments. Thegas manifold 294 is depicted in FIG. 12 as having a first manifoldportion 310 that receives generally higher pressure gas from theseparator 170 and a second manifold portion 312 that receives generallylower pressure gas from the tanks (e.g., tanks 290 and 292). Valves 314,316, 318, and 320 can be operated (manually or via remote control) toselectively route gas to a desired burner 176 (e.g., port or starboard)for flaring. The oil manifold 296 is depicted in FIG. 13 as havingpipework and valves 328, 330, 332, 334, 336, and 338. These valves canbe operated (manually or via remote control) to route oil betweenvarious locations, such as from the separator to the tanks, from thetanks to a desired burner 176, or between two tanks. The oil transferpump 298 can pump oil through the system and is shown in FIG. 13 asincluding a bypass valve 340. The water manifold 302 is depicted in FIG.14 as having pipework and valves 348, 350, 352, 354, 356, and 358. Thesevalves can be operated similarly to those of the oil manifold to routewater between various locations (e.g., from the separator to the tanks,from the tanks to disposal, and between two tanks). The water transferpump 304 can be used to pump water through the system. In at least someembodiments, the valves of the manifolds 294, 296, and 302 arepneumatically actuated and are operated and controlled using a controlsystem, such as that described above.

In FIG. 15 , an implementation 360 of the pump manifold skid 284 isdepicted as having a platform 362 and a frame 364. This implementationof the pump manifold skid 284 is designed for use on offshore rigs andcan accommodate roll, pitch, and heave conditions on such rigs (e.g., inaccordance with offshore standard DNVGL-OS-E101). The platform 362 isdepicted as having slots to facilitate transport and handling of theskid 284. The gas manifold 294 (with its portions 310 and 312), the oilmanifold 296, the oil transfer pump 298, the water manifold 302, and thewater transfer pump 304 are shown mounted on the platform 362. The pumpmanifold skid 284 includes the power system (electrical, pneumatic), thecommunication system, and the control system, and various components ofthese systems may be installed in enclosures mounted on the skid 284.For example, a control unit (e.g., controller 74) and communicationdevices may be mounted in a control box 366.

The implementation of the pump manifold skid depicted in FIG. 15 alsoincludes an HMI in the form of a control panel 368. As presently shown,the control panel 368 includes a screen for displaying information to anoperator. The control panel is mounted on the skid such that it iseasily accessible. In at least some embodiments, the pumps and valves ofthe pump manifold skid and the tank manifold skids (as described below)can be actuated from the control panel 368 or from a lab cabin (e.g.,via computer system 208). In another embodiment, these pumps and valvescan be actuated from a mobile device 214 carried by an operator, asdiscussed above. It is also possible to connect external back-up pumpsfor oil or water transfer. Cables and other accessories used for thecontrol system can be included in the pump manifold skid 284. Forexample, the skid 284 may include cables to be connected to tankmanifold skids so as to enable communication of control signals from thecontrol unit mounted on the pump manifold skid 284 to actuators ofvalves mounted on the tank manifold skids so as to selectively controlflow of fluids between components (e.g., between the separator 170 andtanks 290 and 292) of the well testing apparatus.

An implementation 370 of a tank manifold skid 286 or 288 is depicted inFIG. 16 as one example. Although just one skid is depicted in FIG. 16 ,it will be appreciated that the other tank manifold skids deployed in awell testing installation may be identical to the presently depictedimplementation 370. The skid is shown in FIG. 16 as having pipework 372mounted on a platform 374. This pipework 372 and valves for controllingflow through the pipework are discussed in greater detail below withrespect to FIG. 17 . Like the platform 362, the platform 374 includesslots to facilitate transport and handling of the tank manifold skid.And like the pump manifold skid implementation of FIG. 15 , thisimplementation of the tank manifold skid is also designed for offshoreinstallations per the offshore standard DNVGL-OS-E101 noted above. Powerdistribution and communication components, such as for facilitatingremote actuation of the valves of the tank manifold skid, may beenclosed in an electrical box 376 or in some other suitable enclosure.As shown in FIG. 16 , a portion of the pipework 372 can be mounted onthe tank manifold skid below decking 378 to facilitate operator movementand reduce tripping hazards on the skid. Various cables and accessoriesfor the control system may be preinstalled on each tank manifold skidbefore connecting the tank manifold skid to other components. Cableswith connectors, which may be reeled from cable reels 380, can be usedto make power and control connections with the pump manifold skid foreasy offshore installation.

A schematic representation of the valves and pipework 372 of the tankmanifold skid implementation 370 is depicted in FIG. 17 in accordancewith one embodiment. In this example, the pipework 372 enables controlof the inlet and outlet of liquids from a two-compartment tank. As shownin FIG. 17 , the depicted pipework 372 includes first pipework havingpipes 382, 384, 386, 388, and 390. In an installation with multiplefluid tanks and associated tank manifold skids, the first pipework ofone tank manifold skid can be coupled to the first pipework of one ormore other tank manifold skids. This allows the first pipework of themultiple skids to cooperate and enable fluid communication between themultiple tank manifold skids through the first pipework. For example,the pipes 382 of two or more tank manifold skids may be coupled togetherto form a trunk line for routing oil from the separator 170 to thetanks. Similarly, the pipes 384 of multiple tank manifold skids may becoupled together to form a trunk line for routing water from theseparator 170 to the tanks. The pipes 386, 388, and 390 of each tankmanifold skid may be coupled together with the pipes 386, 388, and 390to form trunk lines for routing oil, water, and gas, respectively, awayfrom the tanks for disposal.

The pipework 372 also includes second pipework having pipes 396, 404,410, and 414. These pipes of the second pipework function as branchlines that enable fluid communication between the trunk lines embodiedby the first pipework and a tank connected to the tank manifold skid.Valves 398, 400, 406, and 412 can be operated to control flow of oil andwater between the trunk lines (of pipes 382, 384, 386, and 388) andcompartments of the connected tank. In at least some embodiments, thevalves on the tank manifold skid are pneumatically actuated and can beremotely operated using a control system, such as that described above.For example, the valves 398, 400, 406, and 412 can be remotely operatedfrom the control panel 368 on the pump manifold skid, from a lab cabin(e.g., via computer system 208), or from a mobile device 214. It will beappreciated that a particular tank can be selected for receiving ordistributing oil or water by opening a valve on a branch line of thetank manifold skid of the particular tank, while closing the identicalvalves of the branch lines of the other tank manifold skids.

The tank manifold skids provide flexibility to connect a suitable numberof tanks in different spatial arrangements to suit rig spaceconstraints. Several possible arrangements of four tanks and associatedtank manifold skids with a pump manifold skid are depicted in FIGS.18-20 , but in other instances the depicted components can be arrangedin some other suitable manner. Further, it will be appreciated that awell testing installation could include some other number of tanks andassociated tank manifold skids in still other arrangements.

As generally shown in FIG. 18 , an arrangement 420 includes a pumpmanifold skid 422 with tank manifold skids 424 connected in series, withthe tank manifold skids 424 positioned in-line with one another in asingle row. Each tank manifold skid 424 is connected to its associatedtank 426, and fluids may be routed between the tanks 426 and the pumpmanifold skid 422 via the tank manifold skids 424, as discussed above.The pump manifold skid 422, the tank manifold skids 424, and the tanks426 can take any suitable forms, such as the forms described above.

In arrangement 430 of FIG. 19 , the tank manifold skids 424 and thetanks 426 are provided in a rectangular arrangement. In this depictedembodiment, the tank manifold skids 424 are provided along outer edgesof the arrangement and are connected in series with one another. Piping432 is provided to connect the tank manifold skids 424 on the left inFIG. 19 with those on the right. FIG. 20 also depicts a rectangulararrangement 440 of tank manifold skids 424 and tanks 426, but with thetanks 426 (rather than the tank manifold skids 424) provided on outeredges of the arrangement. In this embodiment, the tank manifold skids424 are connected in series, with piping 442 joining the tank manifoldskids on the left with those on the right. A walkway 444 can be providedbetween the tank manifold skids 424 to facilitate operator access toequipment on these skids.

For ease of installation of the well testing apparatus at a wellsite(e.g., on an offshore rig), in some instances a modular portion of thewell testing apparatus can be assembled at a non-wellsite location, suchas in a remote onshore facility. The assembled modular portion may betransported as a single unit from that non-wellsite location to thewellsite and then connected to additional components as part of the welltesting apparatus. In some embodiments, assembling the modular portionof the well testing apparatus at the non-wellsite location can includecoupling surge tanks (e.g., tanks 290 and 292) to their respective tankmanifold skids (e.g., tank manifold skids 286 and 288) and also couplingthose tank manifold skids together so that the surge tanks and theirtank manifold skids are connected together as a single unit. This singleunit could then be transported to an offshore rig or other wellsite forinstallation as part of a well testing apparatus.

In other embodiments, assembling the modular portion at the non-wellsitelocation may include coupling three or more tank manifold skids andtanks to one another as a single unit, or coupling a pump manifold skidwith multiple tanks and tank manifold skids as a single unit. In anotherembodiment, assembling the modular portion of the well testing apparatusat the non-wellsite location can include assembling a part of themodular portion at a first non-wellsite location and assembling anotherpart of the modular portion at a second non-wellsite location. And in atleast some instances, any of the modular portions above (including itsassembled components and their connections) can be pre-certified (e.g.,as assembled in accordance with Det Norske Veritas (DNV) standard forcertification No. 2.7-3 (May 2011)) for transport as a single unit.

The foregoing outlines features of several embodiments so that thoseskilled in the art may better understand aspects of the presentdisclosure. Those skilled in the art should appreciate that they mayreadily use the present disclosure as a basis for designing or modifyingother processes and structures for carrying out the same purposes orachieving the same advantages of the embodiments introduced herein.Those skilled in the art should also realize that such equivalentconstructions do not depart from the spirit and scope of the presentdisclosure, and that they may make various changes, substitutions andalterations herein without departing from the spirit and scope of thepresent disclosure.

1. A system comprising: a well testing apparatus including: a separatorconfigured to receive a multiphase fluid comprising at least two ofwater, oil, and gas; a well control assembly coupled upstream of theseparator so as to route the multiphase fluid from a well to theseparator; a fluid management assembly coupled downstream of theseparator so as to receive separated fluids from the separator; a burnercoupled downstream of the fluid management assembly so as to receive andburn at least one of the separated fluids from the fluid managementassembly, wherein the at least one of the separated fluids comprisesoil, gas, or a mixture thereof; and data acquisition devices positionedto collect data about operation of the well testing apparatus; and amobile device to be carried by an operator of the well testingapparatus, wherein the mobile device is configured to displayinformation about the operation of the well testing apparatus based onthe collected data, along with video of at least one portion of the welltesting apparatus, and enable mobile monitoring of the operation of thewell testing apparatus by the operator as the operator moves about thewell testing apparatus, and wherein the mobile device is configured to:receive a user input corresponding to a request to route the at leastone of the separated fluids to the burner; determine whether the requestis compatible with one or more rules provided in an interlock matrix;present an error message in response to the request being incompatiblewith the one or more rules; and send one or more actuation signalsconfigured to cause at least one manifold of the fluid managementassembly to route the at least one of the separated fluids to the burnerin response to the request being compatible with the one or more rules.2. The system of claim 1, wherein the one or more rules corresponds topreventing two fluids from simultaneously being received by the burnerand an additional burner of the system.
 3. The system of claim 1,wherein the one or more rules corresponds to preventing two valves ofthe fluid management system from being opened simultaneously.
 4. Thesystem of claim 1, wherein the one or more actuation signals areconfigured to initiate a sequence for opening or closing at least twovalves of the fluid management assembly to route the at least one of theseparated fluids to the burner.
 5. The system of claim 1, wherein theone or more actuation signals are configured to cause a pump to operateto route the at least one of the separated fluids to the burner.
 6. Thesystem of claim 1, wherein the data acquisition devices comprise acamera configured to view the burner and collect image data about anoperation of the burner.
 7. The system of claim 1, wherein the one ormore rules corresponds to preventing a type of fluid from being receivedby the burner.
 8. The system of claim 7, wherein the fluid comprises agas.
 9. A method, comprising: receiving, via a computing system, a userinput corresponding to a request to route a separated fluid from aseparator configured to receive a multiphase fluid comprising at leasttwo of water, oil, and gas to a burner coupled downstream from theseparator, wherein the burner is configured to burn the separated fluidreceived via a fluid management assembly coupled downstream from theseparator, and wherein the burner, the separator, and the fluidmanagement assembly are part of a well testing apparatus for performinga well test of a well at a well site; determining, via the computingsystem, whether the request is compatible with one or more rulesprovided in an interlock matrix; presenting, via the computing system,an error message via a display of a mobile device in response to therequest being incompatible with the one or more rules; and sending, viathe computing system, one or more actuation signals to the fluidmanagement assembly, wherein the fluid management assembly is configuredto cause at least one manifold to route the separated fluid to theburner in response to the request being compatible with the one or morerules; receiving, via the computing system, data from sensors configuredto monitor the burner; presenting, via the computing system, a visualrepresentation of the data via the display; and concurrently, via thecomputing system, presenting video of the burner via the display,wherein the video is collected by a camera pointed at the burner that isburning the separated fluid.
 10. The method of claim 9, whereinpresenting the visual representation of the data comprises displayingreal-time values of the data.
 11. The method of claim 9, wherein the oneor more rules corresponds to preventing two fluids from simultaneouslybeing received by the burner and an additional burner of the system. 12.The method of claim 9, comprising controlling operation of the welltesting apparatus based on user input received from one of the multipleoperators via one of the multiple mobile devices.
 13. The method ofclaim 12, comprising: processing the data; wirelessly transmitting theprocessed data to the mobile device; and present the processed data viathe display of the mobile device.
 14. The method of claim 9, wherein theone or more rules corresponds to determining whether the requestcomprises two incompatible operational procedures are being performed bythe well testing apparatus.
 15. The method of claim 9, wherein the oneor more rules corresponds to determining whether an operational state ofthe well testing apparatus corresponds to an expected state.
 16. Themethod of claim 9, further comprising maintaining a record of the errormessage, actions performed by the computing system, or both.
 17. Anon-transitory computer-readable medium comprising computer-executableinstructions that, when executed, are configured to cause a processingsystem to perform operations comprising: receiving a user inputcorresponding to a request to route a separated fluid from a separatorconfigured to receive a multiphase fluid comprising at least two ofwater, oil, and gas to a burner coupled downstream from the separator,wherein the burner is configured to burn the separated fluid receivedvia a fluid management assembly coupled downstream from the separator,and wherein the burner, the separator, and the fluid management assemblyare part of a well testing apparatus for performing a well test of awell at a well site; determining, via the computing system, whether therequest is compatible with one or more rules provided in an interlockmatrix; presenting, via the computing system, an error message via adisplay of a mobile device in response to the request being incompatiblewith the one or more rules; and sending, via the computing system, oneor more actuation signals to the fluid management assembly, wherein thefluid management assembly is configured to cause at least one manifoldto route the separated fluid to the burner in response to the requestbeing compatible with the one or more rules.
 18. The non-transitorycomputer-readable medium of claim 17, wherein the computer executableinstructions are configured to cause the processing system to performthe operations further comprising: receiving, via the computing system,data from sensors configured to monitor the burner; presenting, via thecomputing system, a visual representation of the data via the display.19. The non-transitory computer-readable medium of claim 17, wherein theone or more rules corresponds to determining whether an operationalstate of the well testing apparatus corresponds to an expected state.20. The non-transitory computer-readable medium of claim 17, wherein theone or more rules corresponds to preventing two fluids fromsimultaneously being received by the burner and an additional burner ofthe system.